Evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale

ABSTRACT

An evaluation method for hydrogen-bearing components, porosity and pore size distribution of organic-rich shale is provided, relating to a technical field of oil and gas development. The evaluation method includes steps of: according to differences among NMR (nuclear magnetic resonance) T1-T2 maps of kerogen, oil-adsorbed kerogen, clay minerals of different water-containing conditions, shale, dry shale sample, oil-saturated shale sample and water-saturated shale sample, establishing a classification scheme for each hydrogen-bearing component and a quantitative characterization method for fluid components of the organic-rich shale; with a T2 distribution of the organic-rich shale after being saturated with oil as a target and a T2 distribution of the dry shale sample as a basement, subtracting the basement, and obtaining a T2 distribution of oil in pores; and based on the T2 distribution of oil in the pores, evaluating the porosity and the pore size distribution of the organic-rich shale. Compared with a conventional method, the present invention shows relatively high innovativeness and credibility, which is beneficial to perfecting analysis of NMR in shale petrophysical measurement.

CROSS REFERENCE OF RELATED APPLICATION

This is a U.S. National Stage under 35 U.S.C 371 of the InternationalApplication PCT/CN2018/119193, filed Dec. 4, 2018, which claims priorityunder 35 U.S.C. 119(a-d) to CN 201810260408.0, filed Mar. 27, 2018.

BACKGROUND OF THE PRESENT INVENTION Field of Invention

The present invention relates to a technical field of oil and gasdevelopment, and more particularly to an evaluation method forhydrogen-bearing components, porosity and pore size distribution oforganic-rich shale.

Description of Related Arts

Currently, the common techniques in the industry are described asfollows.

The shale oil and gas is a hydrocarbon which is generated but retainedin the micro-nano pores of the shale strata. In recent years, because ofthe huge resource amount, the shale oil and gas has attracted moreattentions. In the initial stage of shale oil exploration, the shale oilin the organic-rich shale strata (TOC>2%, TOC=Total Organic Carbon) isthe primary research subject, which is economically recoverable.Compared with the conventional sandstone reservoir, the organic-richshale represents the characteristics of complex hydrogen-bearingcomponents (high clay mineral content and rich organic matters) andcompactness (low porosity and low permeability), causing that theconventional NMR (nuclear magnetic resonance) evaluation method haslimitations on the hydrogen-bearing component identification and theporosity and pore size distribution characterization of the organic-richshales.

Conventionally, the identification for the NMR signals of thehydrogen-bearing components in the shale is mainly based on the signalshielding method and the two-dimensional NMR method (Kausik et al.,2011; Cao et al., 2012; Gannaway, 2014; Karimi et al., 2015; Washburn etal., 2015; Daigle et al., 2016; Korb et al., 2014; Mansoor et al., 2016;and Nicot et al., 2016). The signal shielding method is to immerse theshale into the manganese chloride solution (MnCl₂) or saturate the shalewith deuteroxide (D₂O), so that only the signal of oil is detectedthrough the NMR.

(1) The identification based on the signal shielding method and thetwo-dimensional NMR method mainly faces following problems. {circlearound (1)} When the manganese chloride or deuteroxide cannot enter thesmall pores or isolated pores in the shales, the signal of water may notbe shielded. {circle around (2)} The lacustrine shale is enriched inclay minerals, and Mn²⁺ will undergo hydrolysis with some clay minerals,which damages the pore structure of the shales (Wang et al., 2003).{circle around (3)} These two methods can only separate the signals ofoil and water, but cannot distinguish the signal of kerogen. Thetwo-dimensional NMR method is to measure another parameter (e.g.,diffusion coefficient D, longitudinal relaxation time T₁ and magneticfield gradient G) as well as the transverse relaxation time (T₂), andthen separate each component according to the differences among thenuclear magnetic responses of different components. For the conventionalreservoirs, the D-T₂ method is commonest. However, due to thecharacteristics of low porosity and much paramagnetic of shalereservoirs, the D-T₂ method cannot achieve the relatively good effect(Kausik et al., 2011; and Washburn et al., 2015). Conventionally, fordistinguishing the hydrogen-bearing components of the shale, the widelyused method by scholars is the NMR T₁-T₂ map (Kausik et al., 2011;Washburn et al., 2015; and Korb et al., 2014). However, there is littleresearch on distinguishing the adsorbed fluid components and free fluidcomponents in the shale; meanwhile, the research subject thereof is themarine shale, and whether it is applicable to the clay-rich lacustrineshale in China is still worth discussing.

In evaluation of the porosity and pore size distribution of the shale,some scholars have made several attempts (Yao et al., 2010; Rylander etal., 2013; Hinai et al., 2014; Saidian 2014; Xu et al., 2014; Tan etal., 2015; Zhang et al., 2016; Gao et al., 2016; Zhou et al., 2016; andNing et al., 2017). The current experimental process is to optimize thetest parameters (main objects are echo time (TE) and waiting time (TW))of the NMR experiment with utilizing the porosity test results by thehelium method, then measure the T₂ distribution of the water-saturatedshale, and evaluate the porosity and pore size distribution of the shale(Li et al., 2012; Sun et al., 2010; Zhou et al., 2016; and Gao et al.,2016).

(2) The method of optimizing the test parameters of the NMR experimentwith utilizing the porosity test results by the helium method facesfollowing problems. {circle around (1)} The clay mineral content of theorganic-rich shale is relatively high; with the water saturation method,it easily generates the hydration and expansion phenomenon (Qian et al.,2017), which damages the original pore structural features of the shaleand causes the distortion of the porosity and pore size distribution ofthe NMR test. {circle around (2)} The value of TE calibrated with thetest results by the helium method is generally 0.2 ms (some scholarsadopt a larger value). Under the above TE test condition, the porosityof the NMR test is equal to that of the helium method; buttheoretically, the test results thereof lost the signals of fluids insome nanometer pores with the relatively short relaxation time, andinclude part of the solid matrix signals. {circle around (3)} Thecontent of the organic matters in the organic-rich shale is high; theNMR T₂ distribution obtained through directly testing the shale sampleincludes many signals of solid organic matters and mineral structuralwater, and these signals are not the fluid components in the pores,which cannot be directly used in calculation of the porosity and poresize distribution.

In conclusion, because of the complexity of the organic-rich shalereservoir and many problems of the conventional NMR technology existingin the hydrogen-bearing component identification and the porosity andpore size distribution evaluation of the shale, it is urgent to developan NMR evaluation method for the hydrogen-bearing componentidentification, the porosity and the pore size distribution of theorganic-rich shale.

From the above description, it can be known that the prior art hasproblems that: there exist deficiencies in the identification of thehydrogen-bearing components in the shale by the MnCl₂-immersed shale orD₂O-saturated shale, and the T₂-D technology; the organic-rich shaleexpands after being saturated with water, and the pore structure isdistorted; there exist deficiencies in the fluid detection of themicro-nano pores with the relatively short relaxation time in theorganic-rich shale; and, the influences of the solid organic matter(kerogen) and mineral structural water on the porosity and pore sizedistribution characterization of the organic-rich shale are ignored.

The difficulties and meanings in solving the above technical problemsare described as follows.

Compared with the conventional sandstone reservoir, the organic-richshale has a large number of micro-nano pores and includes a great numberof nuclear magnetic relaxation signals of organic matters/mineralstructural water, and moreover, the nuclear magnetic relaxation featuresof the fluid in the micro-nano pores are relatively similar to that ofthe organic matters/mineral structural water, which increases thedifficulties of the NMR technology in detection of the fluid signals ofthe small pores and interpretation of the hydrogen signals, resulting inthat the evaluation method for the hydrogen-bearing componentidentification, the porosity and the pore size distribution is notperfect enough. Therefore, it is urgent to develop an evaluation methodapplicable to the organic-rich shale.

The meanings of the evaluation method are described as follows. Theestablishment of the NMR identification scheme for the hydrogen-bearingcomponents in the shale is beneficial to the intuitive understanding ofthe relaxation features of each hydrogen-bearing component in the shale,especially the distribution features and contents of oil and water. Forthe organic-rich shale, under the condition of considering the NMRsignals of kerogen and mineral structural water, with the fluid in thepores as the research subject, the above NMR technology has importantsignificance on the physical characterization and microcosmic reservoirevaluation of the organic-rich shale. Meanwhile, the establishment ofthe NMR identification scheme for the hydrogen-bearing components in theshale provides the important technical supports for the oil and wateroccurrence form and mechanism research.

SUMMARY OF THE PRESENT INVENTION

A first object of the present invention is to provide an evaluationmethod for hydrogen-bearing components, porosity and pore sizedistribution of organic-rich shale, so as to solve problems in priorart.

The evaluation method for the hydrogen-bearing components, the porosityand the pore size distribution of the organic-rich shale comprises stepsof:

according to differences among NMR (nuclear magnetic resonance) T₁-T₂maps of kerogen, oil-adsorbed kerogen, clay minerals of differentwater-containing conditions, shale, dry shale sample, oil-saturatedshale sample and water-saturated shale sample, establishing aclassification scheme for each hydrogen-bearing component and aquantitative characterization method for fluid components of theorganic-rich shale, which is beneficial to intuitive understanding ofrelaxation features of each hydrogen-bearing component in theorganic-rich shale and identification of oil and water; and

because NMR signals of organic matters and clay mineral structural waterexist in the organic-rich dry shale sample, with a T₂ distribution ofthe organic-rich shale after being saturated with oil as a target and aT₂ distribution of the dry shale sample as a basement, subtracting thebasement, and obtaining a T₂ distribution of oil in pores; and based onthe T₂ distribution of oil in the pores, evaluating the porosity and thepore size distribution of the organic-rich shale, which is beneficial toan accurate determination of a fluid content and a pore sizedistribution range in the shale.

Preferably, the evaluation method for the hydrogen-bearing components,the porosity and the pore size distribution of the organic-rich shaleparticularly comprises steps of:

through contrastive analysis of the NMR T₁-T₂ maps of kerogen,oil-adsorbed kerogen, clay minerals of different water-containingconditions, and organic-rich shales of differentoil-containing/water-containing conditions, determining the relaxationfeatures of each hydrogen-bearing component, and establishing theclassification scheme for signals of each hydrogen-bearing component inthe organic-rich shale;

processing the organic-rich shale with oil extracting and drying, andobtaining the dry shale sample; dividing the dry shale sample into twoparts, wherein one part is processed with pressurization and oilsaturation for an NMR experiment, and the other part is for experimentsof porosity with a helium method, low-temperature nitrogen adsorption,high-pressure mercury injection, and scanning electron microscope; and

with the T₂ distribution of the organic-rich shale after being saturatedwith oil as the target and the T₂ distribution of the dry shale sampleas the basement, subtracting the basement, and obtaining the T₂distribution of oil in the pores; based on the T₂ distribution of oil inthe pores, combined with a relationship between an NMR signal intensityand a volume of oil, evaluating the porosity of the organic-rich shale;and, combined with the experiments of low-temperature nitrogenadsorption, high-pressure mercury injection, and scanning electronmicroscope, establishing an NMR characterization method for the poresize distribution of the organic-rich shale.

Preferably, the kerogen and the oil-adsorbed kerogen are preparedthrough steps of:

crushing the organic-rich shale sample to above 100 meshes; immersing indistilled water for 4 hours; successively processing with an acidtreatment (successively with 6 mol/L hydrochloric acid, 6 mol/Lhydrochloric acid and 40% hydrofluoric acid), an alkali treatment (with0.5 mol/L sodium hydroxide), and a pyrite treatment (with 6 mol/Lhydrochloric acid and arsenic-free zinc powder); thereafter addingdichloromethane, and stirring; after the dichloromethane is volatilized,obtaining the oil-adsorbed kerogen; processing the oil-adsorbed kerogenwith chloroform extraction for 24 hours, and obtaining the kerogen.

Preferably, the clay minerals of different water-containing conditionsare prepared through steps of:

Because a content of illite-montmorillonite mixed-layer mineral in theorganic-rich shale is relatively high, with montmorillonite as anexample, firstly saturating the montmorillonite with water (free waterand adsorbed water); and then drying for 24 hours respectively at 121°C. and 315° C.; wherein: under a water saturation condition, freewater-containing montmorillonite is obtained; after drying at 121° C.for 24 hours, adsorbed water-containing illite is obtained; and, afterdrying at 315° C. for 24 hours, illite merely containing structuralwater is obtained.

Preferably, the organic-rich shales of differentoil-containing/water-containing conditions are prepared through stepsof:

because residual oil in the organic-rich shale is relatively heavy,firstly processing an as-received shale sample with chloroformextraction for 24 hours; then extracting the shale sample afterchloroform extraction with a ternary organic solution MAB (a ratio ofmethyl alcohol, acetone and benzene is 15:15:70) having a relativelystrong polarity for 24 hours, so as to remove the residual oil in thepores of the shale as far as possible; after ternary extraction,processing the shale sample after extraction with a high-temperaturedrying experiment until reaching a constant weight, wherein a dryingtemperature is set to be 315° C. and kept for 24 hours, so as to removeresidual free water in the pores of the shale and residualbound/adsorbed water at surfaces of the pores, thereby obtaining the dryshale sample; and preserving the dry shale sample in a dryer (at a roomtemperature).

According to the present invention, the dry shale sample afterextraction and drying is placed into a vacuum pressurization saturationdevice; the dry shale sample is firstly vacuumized for 24 hours with avacuum degree of 1×10⁴ Pa; and, after finishing vacuumizing, the dryshale sample is processed with pressurization and oil saturation orwater saturation, wherein a pressurization time is 36 hours.

Preferably, the quantitative characterization method for the fluidcomponents in the organic-rich shale comprises steps of:

(1) calibrating an NMR signal intensity and a volume of free/bulkoil/water, particularly comprising steps of:

configuring standard samples of oil and water with different volumes of0.2 ml, 0.4 ml, 0.6 ml, 0.8 ml and 1.0 ml, and respectively processingwith an NMR T₂ distribution test; according to the volume and acorresponding NMR T₂ distribution area of the free/bulk oil/water,establishing calibration formulas between the NMR signal intensity andthe volume of the free/bulk oil and water that:V _(O) =k ₁ ×A _(O)  (1);V _(w) =k ₂ ×A _(w)  (2);

wherein: in the formulas, V_(O) is the volume of the free/bulk oil, andV_(w) is the volume of the free/bulk water, both in unit of ml; A_(O) isthe NMR T₂ distribution area of the free/bulk oil, and A_(w) is the NMRT₂ distribution area of the free/bulk water, both in unit of a.u.; k₁ isa conversion coefficient between the NMR signal intensity and the volumeof the free/bulk oil; and k₂ is a conversion coefficient between the NMRsignal intensity and the volume of the free/bulk water; and

(2) calibrating an NMR signal intensity and mass of adsorbed oil,particularly comprising steps of:

processing different dry shale samples with adsorbed oil; fittingrelationships between the mass (m_(a)-m₀) and the NMR signal intensity(T_(2a)-T₂₀) of the adsorbed oil, wherein: m_(a) and T_(2a) arerespectively mass and NMR T₂ distribution signal intensity of the dryshale sample with the adsorbed oil; and, m₀ and T₂₀ are respectivelymass and NMR T₂ distribution signal intensity of the dry shale sample;and obtaining a calibration formula between the NMR signal intensity andthe mass of the adsorbed oil that:m _(a0) =k _(a) ×A _(a0)  (3);

wherein: in the formula (3), m_(ao) is the mass of the adsorbed oil, inunit of mg; A_(a0) is an NMR T₂ distribution area of the adsorbed oil,in unit of a.u.; and k_(a) is a conversion coefficient between the NMRsignal intensity and the mass of the adsorbed oil.

Preferably, evaluation for the porosity of the organic-rich shalecomprises steps of:

acquiring an NMR T₂ distribution of saturating oil and calculating theporosity, particularly comprising steps of:

processing the oil-saturated shale sample with an NMR T₂ distributiontest, and obtaining an NMR T₂ decay curve (S(t, sat)) of theoil-saturated shale sample; subtracting an NMR T₂ decay curve (S(t,dry)) of the dry shale sample from the NMR T₂ decay curve (S(t, sat)) ofthe oil-saturated shale sample, and obtaining the T₂ decay curve (ΔS(t,oil)) of the saturating oil that:

$\begin{matrix}{{{S\left( {t,{dry}} \right)} = {\sum_{i}{A_{i}{\exp\left( {- \frac{t}{T_{2i}}} \right)}}}};} & (4) \\{{{S\left( {t,{sat}} \right)} = {\sum_{j}{A_{j}{\exp\left( {- \frac{t}{T_{2j}}} \right)}}}};} & (5) \\\begin{matrix}{{\Delta\;{S\left( {t,{oil}} \right)}} = {{S\left( {t,{sat}} \right)} - {S\left( {t,{dry}} \right)}}} \\{{= {\sum_{k}{\Delta\; A_{k}{\exp\left( {- \frac{t}{T_{2k}}} \right)}}}};}\end{matrix} & (6)\end{matrix}$

wherein: in the formulas (4)-(6), S(t, dry) is an echo amplitude of thedry shale sample; S(t, sat) is an echo amplitude of the oil-saturatedshale sample; ΔS(t, oil) is an echo amplitude of the saturating oil;A_(i) is an amplitude of the dry shale sample when T₂=T_(2i); A_(j) isan amplitude of the oil-saturated shale sample when T₂=T_(2j); ΔA_(k) isan amplitude of the saturating oil when T₂=T_(2k); t=n*TE, wherein n isnumber of echoes; i, j and k respectively represent orders of signalcollection points, with a value of 1, 2, 3 . . . n.

Preferably, NMR pore size calibration of the organic-rich shalecomprises steps of:

determining an NMR calibration coefficient C; according to the formula(1), converting signal intensities corresponding to all T₂ points in theNMR T₂ distribution of the saturating oil to pore volumes; and, with aspecified calibration coefficient C, converting a T₂ relaxation time toa pore diameter through a formula of:d=C×T ₂  (7);

wherein: in the formula (7), d is the pore diameter, in unit of nm; T₂is an NMR transverse relaxation time, in unit of ms; and C is thecalibration coefficient;

with a horizontal axis of pore diameter and a vertical axis ofdV/(dlogD), graphing a pore size distribution curve R_(NMR) convertedfrom the NMR T₂ distribution of the saturating oil; superimposing curvesof R_(LTNA-MICP) and R_(NMR), and calculating an error value thereofthrough a formula of:

$\begin{matrix}\begin{matrix}{Q = {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - R_{{NMR} - i}} \right)^{2}}}}} \\{{= {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - {C \times T_{2i}}} \right)^{2}}}}};}\end{matrix} & (8)\end{matrix}$

wherein: in the formula (8), Q is the error value; n is a number of datapoints in the R_(LTNA-MICP) pore size distribution curve; R_(LTNA-MICP)is an i^(th) data point in the R_(LTNA-MICP) pore size distributioncurve; and R_(NMR-i), is R_(NMR) data corresponding to the i^(th) datapoint in the R_(LTNA-MICP) pore size distribution curve;

when similarity of the curves of R_(LTNA-MICP) and R_(NMR) is closest,namely the error value is smallest, recording a current value of thecalibration coefficient C as a pore diameter calibration coefficientvalue of the NMR transverse relaxation time.

A second object of the present invention is to provide a computerprogram able to implement the evaluation method for the hydrogen-bearingcomponents, the porosity and the pore size distribution of theorganic-rich shale.

A third object of the present invention is to provide an informationdata processing terminal able to implement the evaluation method for thehydrogen-bearing components, the porosity and the pore size distributionof the organic-rich shale.

A fourth object of the present invention is to provide acomputer-readable storage medium containing instructions, wherein: whenthe computer-readable storage medium runs on a computer, the computer isable to execute the evaluation method for the hydrogen-bearingcomponents, the porosity and the pore size distribution of theorganic-rich shale.

A fifth object of the present invention is to provide an evaluationsystem for the hydrogen-bearing components, the porosity and the poresize distribution of the organic-rich shale, comprising:

a construction module for the classification scheme of thehydrogen-bearing components and the quantitative characterization methodof the fluid components of the organic-rich shale, for establishing theclassification scheme of each hydrogen-bearing component and thequantitative characterization method of the fluid components of theorganic-rich shale according to the differences among the NMR T₁-T₂ mapsof kerogen, oil-adsorbed kerogen, clay minerals of differentwater-containing conditions, shale, dry shale sample, oil-saturatedshale sample and water-saturated shale sample; and

an evaluation module for the porosity and the pore size distribution ofthe organic-rich shale, wherein: because the NMR signals of organicmatters and clay mineral structural water exist in the organic-rich dryshale sample, with the T₂ distribution of the organic-rich shale afterbeing saturated with oil as the target and the T₂ distribution of thedry shale sample as the basement, the T₂ distribution of oil in thepores is obtained through subtracting the basement, and based on the T₂distribution of oil in the pores, the evaluation module evaluates theporosity and the pore size distribution of the organic-rich shale.

A sixth object of the present invention is to provide an informationdata processing terminal equipped with the evaluation system for thehydrogen-bearing components, the porosity and the pore size distributionof the organic-rich shale.

In conclusion, the present invention has following advantages andpositive effects.

The present invention adopts the organic-rich shale as the analysissubject, and provides the NMR evaluation method for the hydrogen-bearingcomponents, the porosity and the pore size distribution of theorganic-rich shale, which solves and perfects following problems.Firstly, the established identification method for each hydrogen-bearingcomponent (kerogen, adsorbed oil, free oil, adsorbed water, free waterand mineral structural water) in the organic-rich shale with utilizingthe NMR T₁-T₂ map technology is able to cover the shortages in theidentification of the hydrogen-bearing components in the shale by theMnCl₂-immersed shale or D₂O-saturated shale, and the T₂-D technology, sothat the accuracy of organic matter signal intensity detection can reachabove 83% (as shown in FIGS. 14-16). Secondly, with the oil saturationmethod, the problems that the organic-rich shale expands after beingsaturated with water and the pore structure is distorted are solved.Thirdly, with the relatively low TE (echo time), the problem of fluiddetection of the micro-nano pores with the relatively short relaxationtime in the organic-rich shale is solved. Fourthly, through processingthe organic-rich dry shale sample (the shale after oil extracting anddrying) with pressurization and oil saturation and adopting therelatively low TE (0.07 ms), with the T₂ distribution of theorganic-rich shale after being saturated with oil as the target and theT₂ distribution of the dry shale sample as the basement, the T₂distribution of oil in the pores is obtained through subtracting thebasement; and based on the T₂ distribution of oil in the pores, theporosity and the pore size distribution are evaluated, which eliminatesthe influences of the solid organic matter (kerogen) and mineralstructural water on the porosity and pore size distributioncharacterization of the organic-rich shale. Compared with theconventional research method, the porosity by the present invention iscloser to the porosity value by the helium measurement method (as shownin FIG. 17), and the pore size distribution shows high consistency inthe small pores (<10 nm) with the low-temperature nitrogen adsorptionexperimental results (as shown in FIG. 18).

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a flow chart of an evaluation method for hydrogen-bearingcomponents, porosity and pore size distribution of organic-rich shaleaccording to the present invention.

FIG. 2 shows NMR (nuclear magnetic resonance) T₁-T₂ maps of kerogen andoil-adsorbed kerogen according to the present invention.

FIG. 3 shows features of an NMR T₁-T₂ map of free water in pores ofmontmorillonite after being saturated with water according to thepresent invention.

FIG. 4 shows NMR T₁-T₂ maps of shale, dry shale sample, oil-saturatedshale sample and water-saturated shale sample according to the presentinvention.

FIG. 5 is an NMR T₁-T₂ map of each hydrogen-bearing component inlacustrine shale according to the present invention.

FIG. 6 is a distribution feature diagram of NMR T₂ distributions offree/bulk oil and free/bulk water with different volumes according tothe present invention.

FIG. 7 is a calibration diagram of NMR signals of the free/bulk oil andthe free/bulk water according to the present invention.

FIG. 8 is a relationship diagram between an NMR signal intensity andmass of adsorbed oil according to the present invention.

FIG. 9 is a weight change curve diagram of samples tested at differentpressurization saturation time periods according to the presentinvention.

FIG. 10 is a comparison diagram between NMR T₂ decay curves of theorganic-rich dry shale sample and the oil-saturated shale sampleaccording to the present invention.

FIG. 11 is a comparison diagram between NMR T₂ distributions of dryshale sample, oil-saturated shale sample, and saturating oil accordingto the present invention.

FIG. 12 is a comparison diagram between pore size distributions of theorganic-rich dry shale sample, obtained respectively by low-temperaturenitrogen adsorption and high-pressure mercury injection, according tothe present invention.

FIG. 13 is a photo of the organic-rich shale by large-areahigh-resolution electron microscope imaging according to the presentinvention.

FIG. 14 is a relationship diagram between an organic matter NMR signalintensity of the organic-rich shale and geochemical parameters accordingto the present invention.

FIG. 15 is an NMR evaluation result diagram of oil saturation of theorganic-rich shale according to the present invention.

FIG. 16 is an NMR evaluation result diagram of the content of theadsorbed oil in the organic-rich shale according to the presentinvention.

FIG. 17 is an NMR evaluation result diagram of the porosity of theorganic-rich shale according to the present invention.

FIG. 18 is an NMR characterization result diagram of the pore sizedistribution of the organic-rich shale according to the presentinvention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

In order to make the objects, technical solutions and advantages of thepresent invention clearer and more understandable, the present inventionis further described in detail with the preferred embodiment. It shouldbe understood that: the preferred embodiment described herein is merelyfor explaining the present invention, not for limiting the presentinvention.

There exist deficiencies in the identification of the hydrogen-bearingcomponents in the shale by the MnCl₂-immersed shale or D₂O-saturatedshale, and the T₂-D technology; the organic-rich shale expands afterbeing saturated with water, and the pore structure is distorted; thereexist deficiencies in the fluid detection of the micro-nano pores withthe relatively short relaxation time in the organic-rich shale; and, theinfluences of the solid organic matter (kerogen) and mineral structuralwater on the porosity and pore size distribution characterization of theorganic-rich shale are ignored.

The present invention is further illustrated in detail as follows.

The present invention provides an evaluation method for hydrogen-bearingcomponents, porosity and pore size distribution of organic-rich shale,comprising steps of:

with considering complexity of the hydrogen-bearing components in theorganic-rich shale, according to differences among NMR (nuclear magneticresonance) T₁-T₂ maps of kerogen, oil-adsorbed kerogen, clay minerals ofdifferent water-containing conditions, shale, dry shale sample,oil-saturated shale sample and water-saturated shale sample,establishing a classification scheme for each hydrogen-bearing component(kerogen, adsorbed oil, free oil, adsorbed water, free water, andmineral structural water) and a quantitative characterization method forfluid components of the organic-rich shale; and because NMR signals(enriched in organic matters and clay mineral structural water) whichare relatively strong exist in the organic-rich dry shale sample, with aT₂ distribution of the organic-rich shale after being saturated with oilas a target and a T₂ distribution of the dry shale sample as a basement,subtracting the basement, and obtaining a T₂ distribution of oil inpores; and based on the T₂ distribution of oil in the pores, evaluatingthe porosity and the pore size distribution of the organic-rich shale.

The present invention is further illustrated in detail as follows.

The evaluation method for the hydrogen-bearing components, the porosityand the pore size distribution of the organic-rich shale based on theNMR can be divided into three parts, respectively the establishment ofthe NMR classification scheme for hydrogen-bearing components in theorganic-rich shale, the NMR porosity evaluation of the organic-richshale, and the NMR pore size distribution characterization of theorganic-rich shale, particularly comprising steps of:

through contrastive analysis of the NMR T₁-T₂ maps of kerogen,oil-adsorbed kerogen, clay minerals of different water-containingconditions, and organic-rich shales of differentoil-containing/water-containing conditions, determining relaxationfeatures of each hydrogen-bearing component, and establishing theclassification scheme for signals of each hydrogen-bearing component inthe organic-rich shale;

processing the organic-rich shale with oil extracting and drying, andobtaining the dry shale sample; dividing the dry shale sample into twoparts, wherein one part is processed with pressurization and oilsaturation for an NMR experiment, and the other part is for experimentsof porosity with a helium method, low-temperature nitrogen adsorption,high-pressure mercury injection, and scanning electron microscope; and

with the T₂ distribution of the organic-rich shale after being saturatedwith oil as the target and the T₂ distribution of the dry shale sampleas the basement, subtracting the basement, and obtaining the T₂distribution of oil in the pores; based on the T₂ distribution of oil inthe pores, combined with a relationship between an NMR signal intensityand a volume of oil, evaluating the porosity of the organic-rich shale;and, combined with the experiments of low-temperature nitrogenadsorption, high-pressure mercury injection, and scanning electronmicroscope, establishing an NMR characterization method for the poresize distribution of the organic-rich shale, as shown in FIG. 1.

The used NMR device in the present invention is a MicroMR23-060H-1 NMRanalyzer of Shanghai Niumag Corporation, wherein: a resonance frequencyis 21.36 MHz; a magnet intensity is 0.28 T; a coil diameter is 25.4 mm;and a magnet temperature is 32° C. The test of T₂ distribution adopts aCPMG sequence; and the test of T₁-T₂ map adopts an IR-CPMG sequence.Test parameters of the device are that: waiting time (TW) is 1000 ms;number of echoes (NECH) is 6000; echo time (TE) is 0.07 ms; P90 is 5.4us; P180 is 10.6 us; number of scans (NS) is 64; and inversion timenumber (NTI) is 16.

The present invention is further illustrated in detail as follows.

Identification of Each Hydrogen-Bearing Component in Organic-Rich Shale

With taking lacustrine organic-rich shale as an example and adopting aseparation method, according to test results of the NMR T₁-T₂ maps ofkerogen, oil-adsorbed kerogen, clay minerals of differentwater-containing conditions, shale, dry shale sample after extractionand drying, water-saturated shale, and oil-saturated shale, establishingthe classification scheme for the signals of each hydrogen-bearingcomponent in the shale; extracting NMR signal intensities of organicmatters, oil and water in the shale; and, based on the relationshipbetween the NMR signal intensity and the volume of oil/water, estimatinga oil/water saturation value of the shale. Detailed technical solutionsare described as follows.

(1) Preparation of Kerogen and Oil-Adsorbed Kerogen

Crushing the organic-rich shale sample to above 100 meshes; immersing indistilled water for 4 hours; successively processing with an acidtreatment (successively with 6 mol/L hydrochloric acid, 6 mol/Lhydrochloric acid and 40% hydrofluoric acid), an alkali treatment (with0.5 mol/L sodium hydroxide), and a pyrite treatment (with 6 mol/Lhydrochloric acid and arsenic-free zinc powder); thereafter addingdichloromethane, and stirring; after the dichloromethane is volatilized,obtaining the oil-adsorbed kerogen; processing the oil-adsorbed kerogenwith chloroform extraction for 24 hours, and obtaining the kerogen.

(2) Preparation of Clay Minerals of Different Water-ContainingConditions

Because a content of illite-montmorillonite mixed-layer mineral in theorganic-rich shale is relatively high, with montmorillonite as anexample, firstly saturating the montmorillonite with water (free waterand adsorbed water); and then drying for 24 hours respectively at 121°C. and 315° C.; wherein: under a water saturation condition, freewater-containing montmorillonite is obtained; after drying at 121° C.for 24 hours, adsorbed water-containing illite is obtained; and, afterdrying at 315° C. for 24 hours, illite merely containing structuralwater is obtained.

(3) Preparation of Shales of Different Oil-Containing/Water-ContainingConditions

Because residual oil in the organic-rich shale is relatively heavy,firstly processing an as-received shale sample with chloroformextraction for 24 hours; then extracting the shale sample with a ternaryorganic solution MAB (a ratio of methyl alcohol, acetone and benzene is15:15:70) having a relatively strong polarity for 24 hours, so as toremove the residual oil in the pores of the shale as far as possible;after ternary extraction, processing the shale sample with ahigh-temperature drying experiment until reaching a constant weight,wherein a drying temperature is set to be 315° C. and kept for 24 hours,so as to remove residual free water in the pores of the shale andresidual bound/adsorbed water at surfaces of the pores, therebyobtaining the dry shale sample; and preserving the dry shale sample in adryer (at a room temperature).

According to the present invention, the dry shale sample afterextraction and drying is placed into a vacuum pressurization saturationdevice; the dry shale sample is firstly vacuumized for 24 hours with avacuum degree of 1×10⁻⁴ Pa; and, after finishing vacuumizing, processingthe dry shale sample with pressurization and oil saturation or watersaturation, wherein a pressurization saturation time is 36 hours.

(4) NMR Relaxation Features of Each Hydrogen-Bearing Component in Shale

The kerogen, oil-adsorbed kerogen, water-saturated montmorillonite,adsorbed water-containing illite, structural water-containing illite,shale, dry shale sample, oil-saturated shale and water-saturated shale,which are prepared through the above steps of (1)-(3), are processedwith the NMR T₁-T₂ map test.

The NMR T₁-T₂ maps of kerogen and oil-adsorbed kerogen are showed inFIG. 2. Under the mutual effect of homonuclear dipolar coupling, thetransverse relaxation time of kerogen is relatively short, wherein: T₂is distributed between 0.01-0.65 ms; a main peak is at about 0.1 ms; T₁has a relatively wide distribution range and is mainly distributedbetween 0.65-100 ms; and a T₁/T₂ ratio is generally above 100. For theoil-adsorbed kerogen, T₂ is mainly distributed between 0.05-2 ms; a mainpeak is located at about 0.15 ms; T₁ is mainly distributed between4.6-125 ms; and a T₁/T₂ ratio at the signal peak is about 155. Throughsubtracting the NMR T₁-T₂ map of the kerogen from the NMR T₁-T₂ map ofthe oil-adsorbed kerogen, the NMR T₁-T₂ map of the adsorbed oil isobtained (if a difference value is negative, set to be 0), wherein: forthe adsorbed oil, T₂ is mainly distributed between 0.22-1 ms; a mainpeak is distributed at 0.65 ms; T₁ is mainly distributed between 10-125ms; a T₁/T₂ ratio is between 25-200; and the T₁/T₂ ratio at the signalpeak is about 50.

Features of the NMR T₁-T₂ map of free water in the pores ofmontmorillonite after being saturated with water are showed in FIG. 3,wherein: T₂ is mainly distributed between 0.22-1 ms; a main peak islocated at 0.65 ms, a T₁/T₂ ratio is between 1-4.64; the T₁/T₂ ratio atthe signal peak is about 1.94. After drying at 121° C., the interlayerwater/free water is removed from montmorillonite, and montmorillonite istransformed into illite. For the adsorbed water-containing illite, T₂ isbetween 0.01-0.11 ms; a main peak is located at about 0.072 ms; T₁ isbetween 0.024-0.64 ms; a T₁/T₂ ratio is smaller than 10; and the T₁/T₂ratio at the signal peak is about 3. After drying at 315° C., theadsorbed water at the surface of illite is removed, and the signal ofstructural water is detected by the NMR T₁-T₂ map test thereof. For thestructural water, T₂ is between 0.01-0.11 ms; a main peak is located atabout 0.058 ms; T₁ is between 0.058-26.83 ms; a T₁/T₂ ratio is smallerthan 100; and the T₁/T₂ ratio at the signal peak is about 10.

The NMR T₁-T₂ maps of shale, dry shale sample, oil-saturated shalesample, and water-saturated shale sample are showed in FIG. 4. The NMRT₁-T₂ map of shale is mainly distributed in five areas that: kerogensignal (T₂<1 ms, T₁/T₂>100); adsorbed oil signal (0.22 ms<T₂<1 ms,25<T₁/T₂<100); free oil signal (T₂>1 ms, 10<T₁/T₂<100); structural watersignal (T₂<0.22 ms, T₁/T₂<100); and adsorbed water signal (T₂<0.22 ms,T₁/T₂<10). After processing the shale with chloroform extraction anddrying at 315° C., compared with the NMR T₁-T₂ map of shale, the signalintensity of the free oil area (T₂>1 ms, 10<T₁/T₂<100) in the NMR T₁-T₂map of dry shale sample is obviously decreased. However, the oil signalstill exists in the free oil area of the dry shale sample, which may bepart of the residual oil existing in the isolated pores and notcompletely removed during the processes of chloroform extraction anddrying. After being saturated with oil, the signal intensity of the freeoil area (T₂>1 ms, 10<T₁/T₂<100) is obviously increased. After beingsaturated with water, the signal intensities at the area of 0.22 ms<T₂<1ms and T₁/T₂<10 and the area of 1 ms<T₂<10 ms and T₁/T₂<10 are obviouslyincreased, indicating the free water. The signal intensity at the areaof 0.22 ms<T₂<1 ms and T₁/T₂<10 is same as that of the water-saturatedmontmorillonite (as shown in FIG. 3), may indicating water in the claymineral intercrystalline pores. For the area of 1 ms<T₂<10 ms andT₁/T₂<10, the T₂ relaxation time is relatively long, reflecting theintergranular pores with the relatively large size.

Classification Scheme for Signals of NMR T₁-T₂ Maps of Organic-RichShale

According to the features of the NMR T₁-T₂ maps of kerogen, oil-adsorbedkerogen, clay minerals of different water-containing conditions, shale,dry shale sample after extraction and drying, oil-saturated shalesample, and water-saturated shale sample, the present invention providesthe distribution range of each hydrogen-bearing component of theorganic-rich shale in the NMR T₁-T₂ map, as shown in FIG. 5.

(5) Quantitative Characterization for Fluid Content in Organic-RichShale

1) Calibrating NMR Signal Intensity and Volume of Free/Bulk Oil/Water

Configuring standard samples of oil and water with different volumes(0.2 ml, 0.4 ml, 0.6 ml, 0.8 ml and 1.0 ml), and respectively processingwith an NMR T₂ distribution test, wherein the T₂ distributions offree/bulk oil and free/bulk water are showed in FIG. 6; according to avolume and a corresponding NMR T₂ distribution area of the free/bulkoil/water, establishing calibration formulas between the NMR signalintensity and the volume of the free/bulk oil and free/bulk water that:V _(O) =k ₁ ×A _(O)  (1);V _(w) =k ₂ ×A _(w)  (2);

wherein: in the formulas, V_(O) is a volume of the free/bulk oil, andV_(w) is a volume of the free/bulk water, both in unit of ml; A_(O) isan NMR T₂ distribution area of the free/bulk oil, and A_(w) is an NMR T₂distribution area of the free/bulk water, both in unit of a.u.; k₁ is aconversion coefficient between the NMR signal intensity and the volumeof the free/bulk oil; and k₂ is a conversion coefficient between the NMRsignal intensity and the volume of the free/bulk water.

As shown in FIG. 7, according to the relationship between the NMR T₂distribution area and the volume of free/bulk oil and free/bulk waterwith different volumes, it is obtained that k₁=0.9322 and k₂=1.1131; therelationship between the NMR signal intensity and the volume of thefree/bulk oil/water (formulas (1)-(2)) is for calculation of the volumeof free/bulk oil and free/bulk water in the pores of the organic-richshale.

2) Calibrating NMR signal intensity and mass of adsorbed oil Crushingthe above dry shale sample to 80-100 meshes; then placing into thevacuum pressurization saturation device, and vacuumizing for 24 hours,wherein the vacuum degree is 1×10⁴ Pa; after finishing vacuumizing,processing the powdery dry shale sample with pressurization and oilsaturation, wherein the pressurization saturation time is 36 hours.

Heating the powdery dry shale sample after being saturated with oil witha constant temperature, wherein the heating temperature is 50° C.;weighing samples of different heating time periods, processing with theNMR T₂ distribution test, and recording changes of the sample mass andthe NMR T₂ distribution, wherein: when the sample mass and the NMR T₂distribution is stable, it is considered that the dry shale sample withadsorbed oil is obtained; the current sample mass m_(a) is recorded, andthe NMR T₂ distribution signal intensity thereof is T_(2a); heating thedry shale sample with adsorbed oil with a temperature of 315° C. for 48hours, and obtaining the dry shale sample, wherein the current samplemass is recorded to be m₀, and the current NMR T₂ distribution signalintensity of the dry shale sample is T₂₀.

Processing different dry shale samples as above; fitting therelationships between the mass (m_(a)-m₀) and the NMR signal intensity(T_(2a)-T₂₀) of the adsorbed oil; and

obtaining a calibration formula between the NMR signal intensity and themass of the adsorbed oil that:m _(a0) =k _(a) ×A _(a0)  (3);

wherein: in the formula (3), m_(a) is mass of the adsorbed oil, in unitof mg; A_(ao) is an NMR T₂ distribution area of the adsorbed oil, inunit of a.u.; and k_(a) is a conversion coefficient between the NMRsignal intensity and the mass of the adsorbed oil.

As shown in FIG. 8, according to the relationships between the NMR T₂distribution area and the mass of adsorbed oil of different samples, itis obtained that k_(a)=0.0102. The relationship between the NMR signalintensity and the mass of the adsorbed oil (formula (3)) is forcalculation of the mass of the adsorbed oil in the pores of theorganic-rich shale.

3) Calculating Fluid Content in Organic-Rich Shale

According to the NMR T₁-T₂ map test results of shale, the classificationscheme for the signals of the NMR T₁-T₂ maps of shale is established;the organic matter signal intensities are extracted from the NMR T₁-T₂map, and contrasted with the pyrolysis experiment; the NMR signalintensities of free oil and free water are extracted from the NMR T₁-T₂map, and the volumes of free oil and free water in the pores arerespectively obtained through the formulas (1) and (2); combined withthe sample porosity, the oil/water saturation value of shale isestimated; the NMR signal intensity of adsorbed oil is extracted fromthe NMR T₁-T₂ map, and with the formula (3), the content of adsorbed oilin the organic-rich shale is obtained.

The evaluation for the porosity of the organic-rich shale is furtherdescribed as follows.

Evaluation for Porosity of Organic-Rich Shale

In the evaluation of the porosity of the organic-rich shale, accordingto the differences between the NMR T₂ distributions of the dry shalesample and the oil-saturated shale sample, with the T₂ distribution ofthe organic-rich shale after being saturated with oil as the target andthe T₂ distribution of the dry shale sample as the basement, subtractingthe basement, and obtaining the T₂ distribution of oil in the pores;and, based on the T₂ distribution of oil in the pores, combined with therelationship between the NMR signal intensity and the volume of oil(formula (1)), evaluating the porosity of the organic-rich shale.Detailed technical solutions are described as follows.

(1) Preparation of Dry Shale Sample

For the original shale taken back from the core library, because of theadsorption effect of rock mineral/kerogen and the accommodation effectof small pores, some water and oil which is relatively heavy are stillremained in the pores. Therefore, if want to directly perform the heliumporosity test and the pressurization saturation fluid processing, theremainly exist following problems. Firstly, the residual water and oiloccupy the volume of pores, causing that the porosity obtained by thehelium porosity test is smaller than the actual porosity. Secondly, thefluid-saturated shale sample is not saturated with the single fluid; theresponse features of the NMR signals of different fluids are different,and it will generate an error during conversion between the NMR signaland the fluid volume, resulting in the distortion of porosity. Thus, itis required to process the original shale with oil washing/extractingand drying.

The preparation process of the dry shale sample has been illustrated indetail at the preparation of the shales of different oil-containing andwater-containing conditions, and thus is not repeated herein.

The dry shale sample after processing is made with the NMR T₁-T₂ maptest, for checking whether the residual oil and water are completelyremoved from the dry shale sample after extraction and drying. As shownin FIG. 4, compared with the shale, only the solid organic matter(kerogen) signal (T₁/T₂>100, T₂<1 ms) and the mineral structural watersignal (T₁/T₂<100, T₂<0.2 ms) are remained in the NMR T₁-T₂ map of thedry shale sample, and the residual oil signal and water signal disappear(T₂>1 ms). If the NMR T₁-T₂ map signals of residual oil and water do notdisappear, it is required to process the shale with extraction anddrying again.

The dry shale sample is processed with the NMR T₂ distribution test, andthe NMR T₂ decay curve (S(t, dry)) of the dry shale sample is obtained.

(2) NMR Porosity Calculation

1) Helium Porosity Measurement

Placing the regular columnar dry shale sample (with a diameter of 2.5cm) into the overburden pressure porosity and permeability measurementdevice, introducing helium into the device, and performing the heliumporosity test in the common way, wherein the test process refers to thepetroleum and natural gas industry standard, SY/T 6485-1999 Measurementmethod for porosity and permeability of rock under overburden pressure.

2) Pressurization and Oil Saturation Experiment of Dry Shale Sample

In order to eliminate the hydration influence of water saturation on theshale sample, processing the dry shale sample after extraction anddrying with pressurization and oil saturation, particularly comprisingsteps of: placing the dry shale sample into the vacuum pressurizationsaturation device; vacuumizing the dry shale sample for 24 hours with avacuum degree of 1×10⁻⁴ Pa; after finishing vacuumizing, processing thedry shale sample with pressurization and oil saturation (with theexample of n-dodecane, similarly hereinafter) for 60 hours, wherein apressurization saturation pressure is 20 MPa; weighing the oil-saturatedshale sample at different pressurization saturation time periods (12hours, 24 hours, 36 hours, 48 hours and 60 hours); and, when the weightis stable (the change range of weights measured at two adjacent timeperiods is lower than 1%), obtaining the 100% oil-saturated shalesample. FIG. 9 is weight change curves of four samples tested atdifferent pressurization saturation time periods, wherein: when thepressurization saturation time reaches 36 hours, the sample weightbecomes stable, and it is considered that the 100% oil-saturated shalesample is obtained.

3) Acquirement of NMR T₂ Distribution of Saturating Oil and Calculationof Porosity

Under the premise that the NMR test parameters of the oil-saturatedshale sample are consistent with that of the dry shale sample,processing the oil-saturated shale sample with the NMR T₂ distributiontest, and obtaining the NMR T₂ decay curve (S(t, sat)) of theoil-saturated shale sample, as shown in FIG. 10. Therefore, throughsubtracting the NMR T₂ decay curve (S(t, dry)) of the dry shale samplefrom the NMR T₂ decay curve (S(t, sat)) of the oil-saturated shalesample, the T₂ decay curve (ΔS(t, oil)) of saturating oil is obtainedthat:

$\begin{matrix}{{{S\left( {t,{dry}} \right)} = {\sum_{i}{A_{i}{\exp\left( {- \frac{t}{T_{2i}}} \right)}}}};} & (4) \\{{{S\left( {t,{sat}} \right)} = {\sum_{j}{A_{j}{\exp\left( {- \frac{t}{T_{2j}}} \right)}}}};} & (5) \\\begin{matrix}{{\Delta\;{S\left( {t,{oil}} \right)}} = {{S\left( {t,{sat}} \right)} - {S\left( {t,{dry}} \right)}}} \\{{= {\sum_{k}{\Delta\; A_{k}{\exp\left( {- \frac{t}{T_{2k}}} \right)}}}};}\end{matrix} & (6)\end{matrix}$

wherein: in the formulas (4)-(6), S(t, dry) is an echo amplitude of thedry shale sample; S(t, sat) is an echo amplitude of the oil-saturatedshale sample; ΔS(t, oil) is an echo amplitude of saturating oil; A_(i)is an amplitude of the dry shale sample when T₂=T_(2i); A_(j) is anamplitude of the oil-saturated shale sample when T₂=T_(2j); ΔA_(k) is anamplitude of saturating oil when T₂=T_(2k); t=n*TE, wherein n is numberof echoes; i, j and k respectively represent orders of signal collectionpoints, with a value of 1, 2, 3 . . . n.

According to the T₂ decay curve ΔS(t, oil) of saturating oil, throughmathematical subtracting, the T₂ distribution of oil in the shale sampleis obtained. As shown in FIG. 11, the NMR signals of the dry shalesample mainly come from the solid organic matter (kerogen) and claymineral structural water, wherein the relaxation time thereof isrelatively short and T₂ is distributed between 0.01-1 ms in form ofsingle peak. After being saturated with oil, two peaks occur in the NMRT₂ distribution, wherein: the front peak keeps the form of dry shalesample, and only the signal intensity is increased; and, because of theinfluence of the pore size, the change amplitude of the front peak isfar smaller than that of the rear peak. For the T₂ distribution ofsaturating oil evaluated by the present invention, compared with the T₂distribution of the oil-saturated shale sample, the rear peak is muchthe same; the signal intensity at the front peak is lower, and thereduced signal is namely the signals of solid organic matter and claymineral structural water in the dry shale sample.

According to the NMR T₂ distribution curve of saturating oil, the T₂distribution area of saturating oil is calculated; combined with thecalibration formula (formula (1)) between the volume and the NMR signalof free oil, the volume of saturating oil is calculated, namely the porevolume of the shale sample; and the porosity is obtained throughdividing the sample volume by the pore volume. The porosity of theorganic-rich shale obtained by the NMR method is contrasted with theporosity tested by the helium method, so as to verify the accuracy andfeasibility of the method.

The present invention is further illustrated with the NMRcharacterization method for the pore size distribution of theorganic-rich shale.

NMR Characterization Method for Pore Size Distribution of Organic-RichShale

In the pore size characterization and evaluation of the organic-richshale, according to the differences between the NMR T₂ distributions ofdry shale sample and oil-saturated shale sample, with the T₂distribution of the organic-rich shale after being saturated with oil asthe target and the T₂ distribution of the dry shale sample as thebasement, the T₂ distribution of oil in the pores is obtained throughsubtracting the basement; and, based on the T₂ distribution of oil inthe pores, combined with experiments for pore size characterization ofdry shale sample, such as low-temperature nitrogen adsorption,high-pressure mercury injection and large-area high-resolution electronmicroscope imaging, the NMR characterization method for the pore sizedistribution of the organic-rich shale is established.

(1) Low-Temperature Nitrogen Adsorption and High-Pressure MercuryInjection Experiments

Cutting and crushing the dry shale sample; firstly preparing into asample with length, width and height of 1 cm 1 cm 1 cm, and performingthe high-pressure mercury injection test (400 Mpa); according to theWashburn model, obtaining the pore size distribution curve R_(MICP) ofthe pores with a diameter larger than 7.2 nm (with a horizontal axis ofpore diameter and a vertical axis of dV/(dlogD), similarly hereinafter),wherein the operation process refers to the industry standard of SY/T5346-2005; utilizing the powdered sample (80-100 meshes) after uniformlymixing, and performing the low-temperature nitrogen adsorptionexperiment; according to the BJH adsorption isotherm, obtaining the poresize distribution curve R_(LTNA) of the pores with a diameter smallerthan 100 nm, as shown in FIG. 12, wherein the operation process refersto the industry standard of GB/T 19587-2004.

(2) Large-Area High-Resolution Electron Microscope Imaging Experiment

Processing the surface of the vertical bedding of the regular sampleblock (1 cm×1 cm×1 cm) with mechanical polishing by the precisecutting-grinding integrated machine; fixing the sample after mechanicalpolishing on the aluminum T-shaped sample stage by the paraffin,polishing for 20 minutes at conditions of 5 KV and 2 mA with the argonion polishing machine, then polishing at conditions of 2 KV and 2 mA for10 minutes, alternately repeating for four times, and finishingpolishing of the sample surface, wherein an included angle between thepolished surface and the argon ion beam is 3°. In order to solve theproblems of small vision filed of scanning electron microscope andheterogeneous sample, the present invention adopts the large-areahigh-resolution electron microscope imaging technology (AMICSCAN), forimaging of the polished surface of the sample at the low voltage of1.2-0.8 KV and the low current of 200-80 pA, wherein the area of theimaging vision field is 300 um×800 um, as shown in FIG. 13. The poresare extracted through the threshold division method, the pore area isobtained, and the curve diagram of pore area verse pore diameter(dS/(dlogD)) is graphed.

(3) Determining Calibration Coefficient C

The pore size distribution curve of the present invention adopts thehorizontal axis of pore diameter (width) and the vertical axis ofdV/(dlogD), wherein the physical meaning of the vertical axis indicatesthe pore number corresponding to a certain pore diameter.

Superimposing the pore size distribution curve R_(MICP) of high-pressuremercury injection with the pore size distribution curve R_(LTNA) oflow-temperature nitrogen adsorption; selecting a connection porediameter r_(p) at a pore diameter range of 10-100 nm, wherein dV/(d logD) values of two pore size distribution curves at the point ofconnection pore diameter r_(p) are required to be roughly the same,ensuring that the pore number measured by the low-temperature nitrogenadsorption method and the high-pressure mercury injection method isalmost identical at the pore diameter r_(p); remaining data points whichare smaller than r_(p) in the low-temperature nitrogen adsorption methodand larger than r_(p) in the high-pressure mercury injection method, andconstructing the full pore size distribution curve R_(LTNA-MICP) of theshale.

According to the formula (1), converting the signal intensitiescorresponding to every T₂ point in the NMR T₂ distribution of saturatingoil (FIG. 11) into the pore volumes; and, with a specified calibrationcoefficient C, converting the T₂ relaxation time to the pore diameterthrough a formula of:d=C×T ₂  (7);

wherein: in the formula (7), d is the pore diameter, in unit of nm; T₂is the NMR transverse relaxation time, in unit of ms; and C is thecalibration coefficient;

with the horizontal axis of pore diameter and the vertical axis ofdV/(dlogD), graphing a pore size distribution curve R_(NMR) convertedfrom the NMR T₂ distribution of the saturating oil; superimposing curvesof R_(LTNA-MICP) and R_(NMR), and calculating an error value thereofthrough a formula of:

$\begin{matrix}\begin{matrix}{Q = {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - R_{{NMR} - i}} \right)^{2}}}}} \\{{= {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - {C \times T_{2i}}} \right)^{2}}}}};}\end{matrix} & (8)\end{matrix}$

wherein: in the formula (8), Q is the error value; n is a number of datapoints in the R_(LTNA-MICP) pore size distribution curve;R_(LTNA-MICP-i) is an i^(th) data point in the R_(LTNA-MICP) pore sizedistribution curve; and R_(NMR-i) is R_(NMR) data corresponding to thei^(th) data point in the R_(LTNA-MICP) pore size distribution curve;

when similarity of the curves of R_(LTNA-MICP) and R_(NMR) is closest,namely the error value is smallest, recording a current value of thecalibration coefficient C as a pore diameter calibration coefficientvalue of the NMR transverse relaxation time.

Combined with the large-area high-resolution electron microscope imagingexperiment, through analyzing and contrasting the NMR pore diameterconversion results calibrated by the low-temperature nitrogen adsorptionand the high-pressure mercury injection with the curve diagram of porearea verse the pore diameter (dS/(dlogD)) obtained by the large-areahigh-resolution electron microscope imaging, the effect of NMR porediameter calibration is verified.

The present invention is further described combined with effects asfollows.

In the hydrogen-bearing component identification and fluid quantitativecharacterization of the organic-rich shale, the present invention takes16 shale samples from Shahejie formation in Damintun Sag of Bohai BayBasin, China as examples. Based on the above signal classificationscheme for each hydrogen-bearing component in the shale and thequantitative characterization method for the fluid content in theorganic-rich shale, the organic matter signal intensity of every sampleis extracted from the T₁-T₂ map, and contrasted with the organicgeochemical parameters (TOC, S1 and S2), as shown in FIG. 14. Theorganic matter signal intensity by the NMR test shows relatively goodlinear positive correlation with the parameters of TOC and S1+S2,further proving the feasibility of the classification scheme for eachhydrogen-bearing component in the shale. Moreover, according to thepresent invention, the signal intensities of free oil and free water arerespectively extracted from the T₁-T₂ maps; with utilizing thecalibration relationships between the NMR signal intensity and thevolume of free oil/water (formulas (1) and (2)), the volumes of free oiland free water are calculated; and, combined with the porosity measuredby the NMR, the oil saturation and water saturation of shale arerespectively estimated. With the oil saturation as the example, as shownin FIG. 15, the evaluation results of oil saturation of the presentinvention are roughly the same as that of the retort method. Meanwhile,the present invention extracts the signal intensity of adsorbed oil fromthe T₁-T₂ maps, and then the mass of adsorbed oil is estimated withutilizing the relationship between the NMR signal intensity and the massof adsorbed oil (formula (3)). As shown in FIG. 16, the content ofadsorbed oil shows a good relationship with the change ΔS₂ (indicatingthe heavy oil) of the pyrolysis parameter S2 before and after oilextracting of the organic-rich shale.

In the porosity evaluation of the organic-rich shale, the presentinvention takes 11 shales from Shahejie formation in Damintun Sag ofBohai Bay Basin, China as the examples. According to the above NMRmeasurement method for the porosity of the organic-rich shale, as shownin FIG. 17, compared with the helium porosity data, the porositypredicted by the T₂ distribution of saturating oil of the presentinvention and the porosity by the helium method are uniformlydistributed at two sides of the diagonal. Moreover, for the porositywhich is obtained through the direct calculation of the oil-saturatedorganic-rich shale sample without removing the signal of dry shalesample (e.g., solid organic matter and mineral structural water), theconventional test results are generally higher than the porosity testedby the helium method; the porosity calculated through the NMR T₂distribution after removing the signal of dry shale sample by thepresent invention is closer to the test results by the helium method,having a higher reliability.

In the characterization of pore size distribution of the organic-richshale, the present invention takes the shale examples from Shahejieformation in Dongying Sag of Bohai Bay Basin, China as the examples.According to the above NMR characterization method for the pore sizedistribution of the organic-rich shale, the conversion coefficient ofthe NMR T₂ time is calibrated together with the low-temperature nitrogenadsorption method and the high-pressure mercury injection method, asshown in FIG. 18. With the horizontal axis of pore width (diameter) andthe vertical axis of dV/(dlogD), the connection point of thelow-temperature nitrogen adsorption R_(LTNA) curve and the high-pressuremercury injection R_(MICP) curve is 25 nm; when the pore diametersmaller than 25 nm, the low-temperature nitrogen adsorption R_(LTNA)curve is utilized; when the pore diameter larger than 25 nm, thehigh-pressure mercury injection R_(MICP) curve is utilized, and thecurve R_(LTNA-MICP) is constructed. Through superimposing the curves ofR_(LTNA-MICP) and R_(NMR), when the error value of two curves issmallest, the conversion coefficient C of the NMR T₂ time is calibratedto be 18. Compared with utilizing the curve diagram of pore area versethe pore diameter (dS/(dlogD)) obtained by the large-areahigh-resolution electron microscope imaging technology (AMICSCAN), theR_(NMR) is closer in trend, further proving the reliability of theconversion coefficient calibrated together with the low-temperaturenitrogen adsorption method and the high-pressure mercury injectionmethod by the present invention. Additionally, compared with the poresize distribution results based on the NMR T₂ distribution ofoil-saturated shale sample, the pore diameter conversion resultsobtained through directly utilizing the NMR T₂ distribution ofsaturating oil (obtained through subtracting the dry shale samplebasement from the oil-saturated shale sample) by the present inventionshows the high consistency with the low-temperature nitrogen adsorptionexperimental results in the small pores (<10 nm), which highlights theinnovation of the present invention in the organic-rich shale's poresize distribution characterized by the NMR technique.

The identification and quantitative characterization forhydrogen-bearing components and the evaluation for porosity and poresize distribution of the organic-rich shale have great significance inthe exploration of shale oil and gas. Conventionally, in view of thedeeper microscope research of the organic-rich shale reservoir and theaccuracy improvement of the NMR device, the present invention utilizesthe low echo time (TE=0.07 ms), considers the complexity ofhydrogen-bearing components in the shale, establishes the classificationscheme for each hydrogen-bearing component in the shale according to thedifferences among the NMR T₁-T₂ maps of kerogen, oil-adsorbed kerogen,clay minerals of different water-containing conditions, shale, dry shalesample, oil-saturated shale sample and water-saturated shale sample, andproposes the identification and quantitative characterization method forthe hydrogen-bearing components in the organic-rich shale based on theNMR T₁-T₂ map. With considering the relatively high NMR signal intensityof the organic-rich dry shale sample (enriched in organic matters andmineral structural water), the present invention adopts the T₂distribution of the organic-rich shale after being saturated with oil asthe target and the T₂ distribution of the dry shale sample as thebasement, obtains the T₂ distribution of oil in the pores throughsubtracting the basement, and evaluates the porosity and pore sizedistribution of the organic-rich shale based on the T₂ distribution ofoil in the pores. The present invention provides the identification andquantitative characterization method for the hydrogen-bearing componentsand the evaluation method for the porosity and the pore sizedistribution of the organic-rich shale based on the NMR, which showsrelatively high innovation and reliability in comparison with theconventional method. Therefore, the present invention is beneficial toperfecting the analysis of NMR in shale petrophysical measurement.

The above-described is only the preferred embodiment of the presentinvention, not for limiting the present invention. Modifications,equivalent replacements, and improvements made within the spirit andprinciple of the present invention are all encompassed in the protectionscope of the present invention.

What is claimed is:
 1. An evaluation method for hydrogen-bearingcomponents, porosity and pore size distribution of organic-rich shale,comprising steps of: according to differences among NMR (nuclearmagnetic resonance) T₁-T₂ maps of kerogen, oil-adsorbed kerogen, clayminerals of different water-containing conditions, shale, dry shalesample, oil-saturated shale sample and water-saturated shale sample,establishing a classification scheme for each hydrogen-hearing componentand a quantitative characterization method for fluid components of theorganic-rich shale; and because NMR signals of organic matters and claymineral structural water exist in the organic-rich dry shale sample,with a T₂ distribution of the organic-rich shale after being saturatedwith oil as a target and a T₂ distribution of the dry shale sample as abasement, subtracting the basement, and obtaining a T₂ distribution ofoil in pores; and, based on the T₂ distribution of oil in the pores,evaluating the porosity and the pore size distribution of theorganic-rich shale.
 2. The evaluation method for the hydrogen-bearingcomponents, the porosity and the pore size distribution of theorganic-rich shale, as recited in claim 1, particularly comprising stepsof: through contrastive analysis of the NMR T₁-T₂ maps of kerogen,oil-adsorbed kerogen, clay minerals of different water-containingconditions, and organic-rich shales of differentoil-containing/water-containing conditions, determining relaxationfeatures of each hydrogen-bearing component, and establishing theclassification scheme for signals of each hydrogen-bearing component andthe quantitative characterization method for the fluid components of theorganic-rich shale; processing the organic-rich shale with oilextracting and drying, and obtaining the dry shale sample; dividing thedry shale sample into two parts, wherein one part is processed withpressurization and oil saturation for an NMR experiment, and the otherpart is for experiments of porosity with a helium method, lowtemperature nitrogen adsorption, high-pressure mercury injection, andscanning electron microscope; and with the T₂ distribution of theorganic-rich shale after being saturated with oil as the target and theT₂ distribution of the dry shale sample as the basement, subtracting thebasement, and obtaining the T₂ distribution of oil in the pores; basedon the T₂ distribution of oil in the pores, combined with a relationshipbetween an NMR signal intensity and a volume of oil, evaluating theporosity of the organic-rich shale; and, combined with the experimentsof low temperature nitrogen adsorption, high-pressure mercury injection,and scanning electron microscope, establishing an NMR characterizationmethod for the pore size distribution of the organic-rich shale.
 3. Theevaluation method for the hydrogen-bearing components, the porosity andthe pore size distribution of the organic-rich shale, as recited inclaim 2, wherein: the kerogen and the oil-adsorbed kerogen are preparedthrough steps of: crushing an organic-rich shale sample to above 100meshes; immersing in distilled water for 4 hours; successivelyprocessing with an acid treatment, an alkali treatment, and a pyritetreatment; thereafter adding dichloromethane, and stirring; after thedichloromethane is volatilized, obtaining the oil-adsorbed kerogen;processing the oil-adsorbed kerogen with chloroform extraction for 24hours, and obtaining the kerogen; the clay minerals of differentwater-containing conditions are prepared through steps of: firstlysaturating the clay mineral with water, and then drying for 24 hoursrespectively at 121° C. and 315° C., wherein: under a water saturationcondition, a free water-containing clay mineral is obtained; afterdrying at 121° C. for 24 hours, an adsorbed water-containing claymineral is obtained; and, after drying at 315° C. for 24 hours, a claymineral merely containing structural water is obtained; and theorganic-rich shales of different oil-containing/water-containingconditions are prepared through steps of: firstly processing anas-received shale sample with chloroform extraction for 24 hours; thenextracting the shale sample after chloroform extraction with a ternaryorganic solution MAB having a relatively strong polarity for 24 hours,wherein a ratio of methyl alcohol, acetone and benzene in the tenaryorganic solution MAB is 15:15:70, so as to remove residual oil in thepores of the shale as far as possible; after ternary extraction,processing the shale sample with a high-temperature drying experimentuntil reaching a constant weight, wherein a drying temperature is set tohe 315° C. and kept for 24 hours, so as to remove residual free water inthe pores of the shale and residual bound/adsorbed water at surfaces ofthe pores, thereby obtaining the dry shale sample; and preserving thedry shale sample in a dryer at a room temperature.
 4. The evaluationmethod for the hydrogen-bearing components, the porosity and the poresize distribution of the organic-rich shale, as recited in claim 2,wherein: the quantitative characterization method for the fluidcomponents in the organic-rich shale comprises steps of: 1) calibratingan NMR signal intensity and a volume of free/bulk oil/water,particularly comprising steps of: configuring standard samples of oiland water with different volumes of 0.2 ml, 0.4 ml, 0.6 ml, 0.8 ml and1.0 ml, and respectively processing with an NMR T₂ distribution test;according to the volume and a corresponding NMR T₂ distribution area ofthe free/bulk oil/water, establishing calibration formulas between theNMR signal intensity and the volume of the free/bulk oil and water that:V _(O) =k ₁ ×A _(O)  (1);V _(w) =k ₂ ×A _(w)  (2); wherein: in the formulas, V_(O) is the volumeof the free/bulk oil, and V_(w), is the volume of the free/bulk water,both in unit of ml; A_(O) is the NMR T₂ distribution area of thefree/bulk oil, and A_(w), is the NMR T₂ distribution area of thefree/bulk water, both in unit of a.u.; k₁ is a conversion coefficientbetween the NMR signal intensity and the volume of the free/bulk oil:and k₂ is a conversion coefficient between the NMR signal intensity andthe volume of the free/bulk water; and 2) calibrating an NMR signalintensity and mass of adsorbed oil, particularly comprising steps of:processing different dry shale samples; fitting relationships betweenthe mass (m_(a)-m₀) and the NMR signal intensity (T_(2a)-T₂₀) of theadsorbed oil, wherein: m_(a) and T_(2a) are respectively mass and NMR T₂distribution signal intensit of the dry shale sample with the adsorbedoil; and, m₀ and T₀ are respectively mass and NMR T₂ distribution signalintensity of the dry shale sample; and obtaining a calibration formulabetween the MIR signal intensity and the mass of the adsorbed oil that:m _(a0) =k _(a) ×A _(a0)  (3); wherein: in the formula (3), m_(ao) isthe mass of the adsorbed oil, in unit of mg; A_(ao) is an NMR T₂distribution area of the adsorbed oil, in unit of a.u.; and k_(a) is aconversion coefficient between the NMR signal intensity and the mass ofthe adsorbed oil.
 5. The evaluation method for the hydrogen-bearingcomponents, the porosity and the pore size distribution of theorganic-rich shale, as recited in claim 2, wherein: evaluation for theporosity of the organic-rich shale comprises steps of: acquiring an NMRT₂ distribution of saturating oil and calculating the porosity,particularly comprising steps of: processing the oil-saturated shalesample with an NMR T₂ distribution test, and obtaining an NMR T₂ decaycurve (S(t, sat)) of the oil-saturated shale sample; subtracting an NMRT₂ decay curve (S(t, dry)) of the dry shale sample from the NMR T₂ decaycurve (S(t, sat)) of the oil-saturated shale sample, and obtaining a T₂decay curve (ΔS(t, oil)) of the saturating oil that: $\begin{matrix}{{{S\left( {t,{dry}} \right)} = {\sum_{i}{A_{i}{\exp\left( {- \frac{t}{T_{2i}}} \right)}}}};} & (4) \\{{{S\left( {t,{sat}} \right)} = {\sum_{j}{A_{j}{\exp\left( {- \frac{t}{T_{2j}}} \right)}}}};} & (5) \\\begin{matrix}{{\Delta\;{S\left( {t,{oil}} \right)}} = {{S\left( {t,{sat}} \right)} - {S\left( {t,{dry}} \right)}}} \\{{= {\sum_{k}{\Delta\; A_{k}{\exp\left( {- \frac{t}{T_{2k}}} \right)}}}};}\end{matrix} & (6)\end{matrix}$ wherein: in the formulas (4)-(6), S(t, dry) is an echoamplitude of the dry shale sample; S(t, sat) is an echo amplitude of theoil-saturated shale sample; ΔS(t, oil) is an echo amplitude of thesaturating oil; A_(i) is an amplitude of the dry shale sample whenT₂=T_(2i); A_(j) is an amplitude of the oil-saturated shale sample whenT₂=T_(2j), ΔA_(k) is an amplitude of the saturating oil when T₂=T_(2k);t=n* TE, wherein n is number of echoes; i, j and k respectivelyrepresent orders of signal collection points, with a value of 1,2,3. . .n; and the NMR characterization method for the pore size distribution ofthe organic-rich shale comprises steps of: determining a calibrationcoefficient C; according to the formula (1), converting signalintensities corresponding to all T₂ points in the NMR T₂ distribution ofthe saturating oil to pore volumes; and, with a specified calibrationcoefficient C, converting a T₂ relaxation time to a pore diameterthrough a formula of:d=C×T ₂  (7); wherein: in the formula (7), d is the pore diameter, inunit of nm; T₂ is an NMR transverse relaxation time, in unit of ms; andC is the calibration coefficient; with a horizontal axis of porediameter and a vertical axis of dV/(dlogD), graphing a pore sizedistribution curve R_(NMR) converted from the NMR T₂ distribution of thesaturating oil; superimposing a pore size distribution curve R_(MICP) ofhigh-pressure mercury injection with a pore size distribution curveR_(LTNA) of low-temperature nitrogen adsorption; selecting a connectionpore diameter r_(p) at a pore diameter range of 10-100 nm, whereindV/(dlogD) values of two pore size distribution curves at the point ofconnection pore diameter r_(p), are required to be roughly the same,ensuring that the pore number measured by a low-temperature nitrogenadsorption method and a high-pressure mercury injection method is almostidentical at the pore diameter r_(p); remaining data points which aresmaller than r_(p) in the low-temperature nitrogen adsorption method andlarger than r_(p) in the high-pressure mercury injection method, andconstructing a full pore size distribution curve R_(LTNA-MICP) of theshale; superimposing curves of R_(LTNA-MICP) and R_(NMR), andcalculating an error value thereof through a formula of: $\begin{matrix}\begin{matrix}{Q = {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - R_{{NMR} - i}} \right)^{2}}}}} \\{{= {\frac{1}{n}{\sum\limits_{i = 1}^{n}\;\sqrt{\left( {R_{{LTNA} - {MICP} - i} - {C \times T_{2i}}} \right)^{2}}}}};}\end{matrix} & (8)\end{matrix}$ wherein: in the formula (8), Q is the error⁻value; n is anumber of data points in the R_(LTNA-MICP) pore size distribution curve;R_(LTNA-MICP) is an i^(th) data point in the R_(LTNA-MICP) pore sizedistribution curve; and R_(NMR-i) is R_(NMR) data corresponding to thei^(th) data point in the R_(LTNA-MICP) pore size distribution curve;when similarity of the curves of R_(LTNA-MICP) and R_(NMR) is closest,namely the error value is smallest, recording a. current value of thecalibration coefficient C as a pore diameter calibration coefficientvalue of the NMR transverse relaxation time.